UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended September 30, 2003
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________________ to __________________
Commission file number: 1-15467
VECTREN CORPORATION
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(Exact name of registrant as specified in its charter)
INDIANA 35-2086905
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(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
20 N.W. 4th Street, Evansville, Indiana, 47708
-------------------------------------------------------
(Address of principal executive offices)
(Zip Code)
812-491-4000
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(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes |X| No __
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes |X| No __
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Common Stock- Without Par Value 75,617,313 October 31, 2003
------------------------------- ---------------- ----------------
Class Number of Shares Date
Table of Contents
Item Page
Number Number
PART I. FINANCIAL INFORMATION
1 Financial Statements (Unaudited)
Vectren Corporation and Subsidiary Companies
Consolidated Condensed Balance Sheets 1-2
Consolidated Condensed Statements of Income 3
Consolidated Condensed Statements of Cash Flows 4
Notes to Unaudited Consolidated Condensed Financial
Statements 5-19
2 Management's Discussion and Analysis of Results of
Operations and Financial Condition 20-42
3 Quantitative and Qualitative Disclosures About
Market Risk 42
4 Controls and Procedures 43
PART II. OTHER INFORMATION
1 Legal Proceedings 43
6 Exhibits and Reports on Form 8-K 44-45
Signatures 46
Definitions
AFUDC: allowance for funds used MMBTU: millions of British thermal
during construction units
APB: Accounting Principles Board MW: megawatts
EITF: Emerging Issues Task Force MWh / GWh: megawatt hours/millions
of megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards NOx: nitrogen oxide
Board
FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility
Commission Consumer Counselor
IDEM: Indiana Department of PUCO: Public Utilities Commission
Environmental Management of Ohio
IURC: Indiana Utility Regulatory SFAS: Statement of Financial
Commission Accounting Standards
MCF / BCF: millions / billions of cubic USEPA: United States Environmental
feet Protection Agency
MDth / MMDth: thousands / millions of Throughput: combined gas sales and
dekatherms gas transportation volumes
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited - In millions)
- -------------------------------------------------------------------------------
September 30, December 31,
2003 2002
- ----------------------------------------------- ------------- ------------
ASSETS
------
Current Assets
Cash & cash equivalents $ 11.7 $ 25.1
Accounts receivable-less reserves of $5.0 &
$5.5, respectively 88.3 154.4
Accrued unbilled revenues 42.3 116.1
Inventories 61.6 62.8
Recoverable fuel & natural gas costs 31.5 22.1
Prepayments & other current assets 166.5 93.0
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Total current assets 401.9 473.5
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Utility Plant
Original cost 3,178.5 3,037.1
Less: accumulated depreciation & amortization 1,456.8 1,389.0
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Net utility plant 1,721.7 1,648.1
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Investments in Unconsolidated Affiliates 166.3 153.3
Other Investments 117.9 124.3
Non-utility Property-Net 215.2 228.0
Goodwill-Net 202.2 202.2
Regulatory Assets 84.7 75.2
Other Assets 22.1 21.9
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TOTAL ASSETS $ 2,932.0 $ 2,926.5
===============================================================================
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited - In millions)
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September 30, December 31,
2003 2002
- -------------------------------------------- ------------- ------------
LIABILITIES & SHAREHOLDERS' EQUITY
---------------------------------
Current Liabilities
Accounts payable $ 61.9 $ 101.7
Accounts payable to affiliated companies 49.6 86.4
Accrued liabilities 108.5 119.9
Short-term borrowings 200.8 399.5
Current maturities of long-term debt - 39.8
Long-term debt subject to tender 10.0 26.6
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Total current liabilities 430.8 773.9
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Long-term Debt-Net of Current Maturities &
Debt Subject to Tender 1,091.5 954.2
Deferred Income Taxes & Other Liabilities
Deferred income taxes 215.1 195.5
Deferred credits & other liabilities 140.0 130.8
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Total deferred credits & other liabilities 355.1 326.3
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Minority Interest in Subsidiary 0.3 1.9
Commitments & Contingencies (Notes 9, 10 & 11)
Cumulative, Redeemable Preferred Stock of
a Subsidiary 0.2 0.3
Common Shareholders' Equity
Common stock (no par value) - issued &
outstanding 75.6 and 67.9, respectively 519.6 350.0
Retained earnings 539.8 530.4
Accumulated other comprehensive income (5.3) (10.5)
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Total common shareholders' equity 1,054.1 869.9
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TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 2,932.0 $ 2,926.5
===============================================================================
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited - In millions, except per share data)
- --------------------------------------------------------------------------------------
Three Months Nine Months
Ended September 30, Ended September 30,
--------------------- --------------------
2003 2002 2003 2002
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As Restated, As Restated,
See Note 3 See Note 3
---------- -----------
OPERATING REVENUES
Gas utility $ 115.7 $ 88.5 $ 790.3 $ 586.7
Electric utility 134.0 189.6 343.6 475.3
Energy services & other 29.1 26.2 90.8 252.8
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Total operating revenues 278.8 304.3 1,224.7 1,314.8
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OPERATING EXPENSES
Cost of gas sold 72.0 45.7 541.4 357.7
Fuel for electric generation 24.9 22.8 66.3 59.7
Purchased electric energy 42.6 93.0 101.8 239.5
Cost of energy services & other 22.0 16.3 66.6 223.1
Other operating 57.2 54.8 179.4 168.4
Depreciation & amortization 32.9 30.4 96.7 88.1
Taxes other than income taxes 9.0 9.8 42.1 38.3
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Total operating expenses 260.6 272.8 1,094.3 1,174.8
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OPERATING INCOME 18.2 31.5 130.4 140.0
OTHER INCOME (EXPENSE)
Equity in earnings (losses) of
unconsolidated affiliates (2.3) 1.7 6.4 8.5
Other - net 8.4 3.7 6.2 9.0
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Total other income (expense) 6.1 5.4 12.6 17.5
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Interest expense 19.6 19.5 56.7 58.8
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INCOME BEFORE INCOME TAXES 4.7 17.4 86.3 98.7
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Income taxes (2.6) 3.6 19.2 27.0
Minority interest in & preferred dividend
requirements of subsidiaries - 0.3 - 0.1
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NET INCOME $ 7.3 $ 13.5 $ 67.1 $ 71.6
=====================================================================================
COMMON SHARES OUTSTANDING:
BASIC 71.6 67.6 69.0 67.6
DILUTED 71.9 67.8 69.3 67.8
EARNINGS PER SHARE OF COMMON STOCK:
BASIC $ 0.10 $ 0.20 $ 0.97 $ 1.06
DILUTED 0.10 0.20 0.97 1.06
DIVIDENDS DECLARED PER SHARE
OF COMMON STOCK $ 0.28 $ 0.27 $ 0.83 $ 0.80
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited - In millions)
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Nine Months Ended
September 30,
---------------------
2003 2002
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As Restated,
See Note 3
-----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 67.1 $ 71.6
Adjustments to reconcile net income to cash
from operating activities:
Depreciation & amortization 96.7 88.1
Deferred income taxes & investment tax credits 18.1 3.8
Equity in earnings of unconsolidated affiliates (6.4) (8.5)
Net unrealized (gain) loss on derivative instruments (0.4) 3.1
Pension and postretirement expense 10.5 9.9
Other non-cash charges- net 6.5 5.6
Changes in working capital accounts:
Accounts receivable & accrued unbilled revenue 129.8 94.4
Inventories 1.2 3.3
Recoverable fuel & natural gas costs (9.4) 29.5
Prepayments & other current assets (77.7) (11.3)
Accounts payable, including to affiliated
companies (76.6) (15.3)
Accrued liabilities (18.8) (0.1)
Changes in other noncurrent assets (2.2) (2.2)
Changes in other noncurrent liabilities (2.4) (8.8)
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Net cash flows from operating activities 136.0 263.1
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CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt issuance - net of issue
costs & hedging proceeds 202.9 -
Common stock issuance- net of issue costs 163.2 -
Stock option exercises & other stock plans 5.2 1.1
Requirements for:
Retirement of long-term debt, including
premiums paid (121.9) (6.3)
Dividends on common stock (57.7) (53.7)
Redemption of preferred stock of subsidiary (0.1) (0.2)
Other financing activities (1.7) -
Net change in short-term borrowings (198.7) (63.7)
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Net cash flows from financing activities (8.8) (122.8)
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CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Notes receivable & other collections 15.3 3.9
Unconsolidated affiliate distributions 13.5 5.3
Requirements for:
Capital expenditures, excluding AFUDC-equity (150.7) (150.2)
Unconsolidated affiliate investments (12.3) (7.5)
Notes receivable & other investments (6.4) (0.4)
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Net cash flows from investing activities (140.6) (148.9)
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Net decrease in cash & cash equivalents (13.4) (8.6)
Cash & cash equivalents at beginning of period 25.1 25.0
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Cash & cash equivalents at end of period $ 11.7 $ 16.4
==================================================================================
The accompanying notes are an integral part of these consolidated condensed
financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
1. Organization and Nature of Operations
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company was organized on June 10, 1999, solely for the purpose of
effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc.
(SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with APB Opinion No. 16
"Business Combinations" (APB 16).
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for its three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned
subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. VUHI also has other assets that provide information technology and
other services to the three utilities. Both Vectren and VUHI are exempt from
registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding
Company Act of 1935.
Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO provides
electric generation, transmission, and distribution services to 8 counties in
southwestern Indiana, including counties surrounding Evansville, and
participates in the wholesale power market. SIGECO also provides natural gas
distribution and transportation services to 10 counties in southwestern Indiana,
including counties surrounding Evansville. The Ohio operations, owned as a
tenancy in common by Vectren Energy Delivery of Ohio, Inc.(VEDO), a wholly owned
subsidiary, (53 % ownership) and Indiana Gas (47 % ownership), provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal to the Company's utility operations
and to other parties and generates IRS Code Section 29 investment tax credits
relating to the production of coal-based synthetic fuels. Utility Infrastructure
Services provides underground construction and repair, facilities locating, and
meter reading services. Broadband invests in broadband communication services
such as analog and digital cable television, high-speed Internet and data
services, and advanced local and long distance phone services. In addition, the
nonregulated group has other businesses that provide utility services, municipal
broadband consulting, and retail products and services and that invest in
energy-related opportunities, real estate, and leveraged leases.
2. Basis of Presentation
The interim consolidated condensed financial statements included in this report
have been prepared by the Company, without audit, as provided in the rules and
regulations of the Securities and Exchange Commission. Certain information and
note disclosures normally included in financial statements prepared in
accordance with accounting principles generally accepted in the United States
have been omitted as provided in such rules and regulations. The Company
believes that the information in this report reflects all adjustments necessary
to fairly state the results of the interim periods reported. These consolidated
condensed financial statements and related notes should be read in conjunction
with the Company's audited annual consolidated financial statements for the year
ended December 31, 2002, filed on Form 10-K/A. Because of the seasonal nature of
the Company's utility operations, the results shown on a quarterly basis are not
necessarily indicative of annual results.
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the statements
and the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from those estimates.
3. Restatement of Previously Reported Information
Subsequent to the issuance of the Company's 2002 quarterly financial statements,
the Company's management determined that previously issued financial statements
should be restated. The restatement had the effect of decreasing net income for
the three months ended September 30, 2002, by $0.5 million after tax, or $0.01
on a basic earnings per share basis, and for the nine months ended September 30,
2002 by $2.3 million after tax, or $0.03 on a basic earnings per share basis.
In the second quarter of 2002, the Company recorded $5.2 million ($3.2 million
after tax) of carrying costs for demand side management (DSM) programs pursuant
to existing IURC orders and based on an improved regulatory environment.
Subsequently, management determined that the accrual of such carrying costs was
more appropriate in periods prior to 2000 when DSM program expenditures were
made. Therefore, such carrying costs originally reflected in 2002 quarterly
results were reversed and reflected in common shareholders' equity as of January
1, 2000. The Company also identified other adjustments for various
reconciliation errors and other errors related primarily to the recording of
estimates. These adjustments were not significant, either individually or in the
aggregate, and decreased previously reported pre-tax and after tax earnings for
the three months ended September 30, 2002, by approximately $0.8 million and
$0.5 million, respectively, and increased previously reported pre-tax and after
tax earnings for the nine months ended September 30, 2002, by approximately $1.8
million and $0.9 million (including a $0.2 million tax adjustment),
respectively.
In addition, the Company reduced previously reported Energy services and other
revenues and Cost of energy services and other by $12.9 million for the nine
months ended September 30, 2002, reflecting the adoption of EITF Issue No. 99-19
"Reporting Revenue Gross as a Principal versus Net as an Agent."
Following is a summary of the effects of the restatement on previously reported
results of operations for the three months ended September 30, 2002.
In millions
- ------------------------------------------------------------------------------------
OPERATING REVENUES As reported Adjustments As Restated
----------- ----------- -----------
Gas utility $ 88.1 $ 0.4 $ 88.5
Electric utility 190.0 (0.4) 189.6
Energy services & other 26.4 (0.2) 26.2
- ------------------------------------------------------------------------------------
Total operating revenues 304.5 (0.2) 304.3
- ------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 45.7 - 45.7
Fuel for electric generation 22.9 (0.1) 22.8
Purchased electric energy 92.5 0.5 93.0
Cost of energy services & other 16.4 (0.1) 16.3
Other operating 54.3 0.5 54.8
Depreciation & amortization 30.4 - 30.4
Taxes other than income taxes 9.8 - 9.8
- ------------------------------------------------------------------------------------
Total operating expenses 272.0 0.8 272.8
- ------------------------------------------------------------------------------------
OPERATING INCOME 32.5 (1.0) 31.5
OTHER INCOME
Equity in earnings of unconsolidated
affiliates 1.7 - 1.7
Other - net 3.5 0.2 3.7
- ------------------------------------------------------------------------------------
Total other income 5.2 0.2 5.4
- ------------------------------------------------------------------------------------
Interest expense 19.5 - 19.5
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INCOME BEFORE INCOME TAXES 18.2 (0.8) 17.4
- ------------------------------------------------------------------------------------
Income taxes 3.9 (0.3) 3.6
Minority interest in and preferred dividends
requirement of subsidiaries 0.3 - 0.3
- ------------------------------------------------------------------------------------
NET INCOME $ 14.0 $ (0.5) 13.5
====================================================================================
Following is a summary of the effects of the restatement on previously reported
results of operations for the nine months ended September 30, 2002.
- ----------------------------------------------------------------------------------
In millions
- ----------------------------------------------------------------------------------
OPERATING REVENUES As reported Adjustments As Restated
----------- ----------- -----------
Gas utility $ 585.0 $ 1.7 $ 586.7
Electric utility 475.7 (0.4) 475.3
Energy services & other 265.9 (13.1) 252.8
- ----------------------------------------------------------------------------------
Total operating revenues 1,326.6 (11.8) 1,314.8
- ----------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas sold 357.6 0.1 357.7
Fuel for electric generation 59.7 - 59.7
Purchased electric energy 239.3 0.2 239.5
Cost of energy services & other 234.9 (11.8) 223.1
Other operating 168.3 0.1 168.4
Depreciation & amortization 88.2 (0.1) 88.1
Taxes other than income taxes 38.3 - 38.3
- ----------------------------------------------------------------------------------
Total operating expenses 1,186.3 (11.5) 1,174.8
- ----------------------------------------------------------------------------------
OPERATING INCOME 140.3 (0.3) 140.0
OTHER INCOME
Equity in earnings of unconsolidated
affiliates 7.8 0.7 8.5
Other - net 12.6 (3.6) 9.0
- ----------------------------------------------------------------------------------
Total other income 20.4 (2.9) 17.5
- ----------------------------------------------------------------------------------
Interest expense 58.6 0.2 58.8
- ----------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 102.1 (3.4) 98.7
- ----------------------------------------------------------------------------------
Income taxes 28.1 (1.1) 27.0
Minority interest in and preferred
dividends requirement of subsidiaries 0.1 - 0.1
- ----------------------------------------------------------------------------------
NET INCOME $ 73.9 $ (2.3) $ 71.6
==================================================================================
4. Stock-Based Compensation
The Company applies APB Opinion 25, "Accounting for Stock Issued to Employees"
(APB25) and related interpretations when measuring compensation expense for its
stock-based compensation plans.
Stock Option Plans
The exercise price of stock options awarded under the Company's stock option
plans is equal to the fair market value of the underlying common stock on the
date of grant. Accordingly, no compensation expense has been recognized for
stock option plans. In January 2003, 384,500 options to purchase shares of
common stock at an exercise price of $23.19 were issued to management. The grant
vests over three years.
Other Plans
In addition to its stock option plans, the Company also maintains restricted
stock and phantom stock plans for executives and non-employee directors. In
January 2003, 93,000 restricted shares with a fair value per share of $23.19
were issued to management. Those shares vest in 2006.
Compensation expense recognized in the consolidated financial statements
associated with these restricted stock and phantom stock plans for the three
months ended September 30, 2003 and 2002, was $1.5 million ($0.9 million after
tax) and income of $0.1 million ($0.1 million after tax), respectively, and for
the nine months ended September 30, 2003 and 2002, was $2.9 million ($1.7
million after tax) and $1.8 million ($1.1 million after tax), respectively. The
amount of expense is consistent with the amount of expense that would have been
recognized if the Company used the fair value based method described in SFAS No.
123 "Accounting for Stock Based Compensation" (SFAS 123), as amended, to value
these awards.
Pro forma Information
Following is the effect on net income and earnings per share as if the fair
value based method described in SFAS 123 had been applied to the Company's
stock-based compensation plans:
- --------------------------------------------------------------------------------------
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
In millions, except per share amounts 2003 2002 2003 2002
- ------------------------------------------- ------------------- -------------------
Net Income:
As reported $ 7.3 $ 13.5 $ 67.1 $ 71.6
Add: Stock-based employee compensation
included in reported net income-
net of tax 0.9 (0.1) 1.7 1.1
Deduct: Total stock-based employee
compensation expense determined
under fair value based method
for all awards- net of tax 1.2 0.2 2.7 1.7
- --------------------------------------------------------------------------------------
Pro forma $ 7.0 $ 13.2 $ 66.1 $ 71.0
======================================================================================
Basic Earnings Per Share:
As reported $ 0.10 $ 0.20 $ 0.97 $ 1.06
Pro forma 0.10 0.20 0.96 1.05
Diluted Earnings Per Share:
As reported $ 0.10 $ 0.20 $ 0.97 $ 1.06
Pro forma 0.10 0.20 0.96 1.05
5. Comprehensive Income
Comprehensive income consists of the following:
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
In millions 2003 2002 2003 2002
- ------------------------------- ------------------- -------------------
Net income $ 7.3 $ 13.5 $ 67.1 $ 71.6
Other comprehensive income
(loss) of unconsolidated
affiliates- net of tax 3.5 (5.0) 5.7 (5.2)
Minimum pension liability
& other - net of tax (0.5) (0.1) (0.1) (0.1)
- ---------------------------------------------------------------------------
Total comprehensive income $ 10.3 $ 8.4 $ 72.7 $ 66.3
===========================================================================
Other comprehensive income arising from unconsolidated affiliates is the
Company's portion of ProLiance Energy, LLC's and Reliant Services, LLC's
accumulated comprehensive income related to the use of cash flow hedges,
including commodity contracts and interest rate swaps, and the Company's portion
of Haddington Energy Partners, LP's accumulated comprehensive income related to
unrealized gains and losses on "available for sale securities."
At December 31, 2002, the Company incurred additional minimum pension
liabilities totaling $30.0 million which is included in deferred credits and
other liabilities. This liability is offset by intangible assets totaling $10.5
million, which is included in other noncurrent assets, and accumulated other
comprehensive income totaling $19.5 million ($11.6 million after tax).
Subsequent to September 30, 2003, the Company's actuary has calculated
preliminary estimates of the Company's minimum pension liability adjustment
expected at December 31, 2003. Based on this calculation, the Company expects an
increase in its minimum pension liability of $9.7 million and corresponding
reduction in equity of $5.8 million after tax.
6. Earnings Per Share
Basic earnings per share is computed by dividing net income available to common
shareholders by the weighted-average number of common shares outstanding for the
period. Diluted earnings per share assumes the conversion of stock options into
common shares and the lifting of restrictions on issued restricted shares using
the treasury stock method to the extent the effect would be dilutive. The
following table sets forth the computation of basic and diluted earnings per
share.
- ---------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
(in millions except per share data) 2003 2002 2003 2002
- ---------------------------------------------- ------------------ -----------------
Numerator:
Numerator for basic and diluted EPS -
Net income $ 7.3 $ 13.5 $ 67.1 $ 71.6
=======================================================================================
Denominator:
Denominator for basic EPS - Weighted
average common shares outstanding 71.6 67.6 69.0 67.6
Conversion of stock options and lifting
of restrictions on issued restricted
stock 0.3 0.2 0.3 0.2
- ---------------------------------------------------------------------------------------
Denominator for diluted EPS - Adjusted
weighted average shares outstanding
and assumed conversions outstanding 71.9 67.8 69.3 67.8
=======================================================================================
Basic earnings per share $ 0.10 $ 0.20 $ 0.97 $ 1.06
Diluted earnings per share $ 0.10 $ 0.20 $ 0.97 $ 1.06
For the three months ended September 30, 2003 and 2002, options to purchase an
additional 110,663 and 87,963, respectively, shares of the Company's common
stock were outstanding, but were not included in the computation of diluted
earnings per share because their effect would be antidilutive. Exercise prices
for options excluded from the computation ranged from $23.35 to $25.59 in 2003
and from $24.05 to $25.59 in 2002.
For the nine months ended September 30, 2003 and 2002, options to purchase an
additional 530,663 and 22,274, respectively, shares of the Company's common
stock were outstanding, but were not included in the computation of diluted
earnings per share because their effect would be antidilutive. Exercise prices
for options excluded from the computation ranged from $23.19 to $25.59 in 2003
and from $24.90 to $25.59 in 2002.
7. Transactions with ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of
Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas
and related services to Indiana Gas, the Ohio operations and Citizens Gas and
also began providing services to SIGECO and Vectren Retail, LLC (the Company's
retail gas marketer) in 2002. ProLiance's primary businesses include gas
marketing, gas portfolio optimization, and other portfolio and energy management
services. ProLiance's primary customers are utilities and other large end use
customers. Vectren's ownership percentage of ProLiance is 61%. Governance and
voting rights remain at 50% for each member. Since governance of ProLiance
remains equal between the members, Vectren continues to account for its
investment in ProLiance using the equity method of accounting.
Purchases from ProLiance for resale and for injections into storage for the
three months ended September 30, 2003 and 2002, totaled $154.1 million and $93.3
million, respectively, and for the nine months ended September 30, 2003 and
2002, totaled $589.0 million and $329.6 million, respectively. Amounts owed to
ProLiance at September 30, 2003 and December 31, 2002, for those purchases were
$49.0 million and $84.6 million, respectively, and are included in accounts
payable to affiliated companies. Amounts charged by ProLiance for gas supply
services are established by supply agreements with each utility.
8. Financing Transactions
Equity Issuance
In March 2003, the Company filed a registration statement with the Securities
and Exchange Commission with respect to a public offering of authorized but
previously unissued shares of common stock. In August 2003, the registration
became effective, and an agreement was reached to sell approximately 7.4 million
shares to a group of underwriters. The net proceeds totaled $163.2 million.
VUHI Debt Issuance
In July 2003, VUHI issued senior unsecured notes with an aggregate principal
amount of $200 million in two $100 million tranches. The first tranche are
10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746%
to yield 5.28% to maturity (2013 Notes). The second tranche are 15-year notes
due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80%
to maturity (2018 Notes).
The notes are jointly and severally guaranteed by the Company's three public
utilities. In addition, they have no sinking fund requirements, and interest
payments are due semi-annually. The notes may be called by the Company, in whole
or in part, at any time for an amount equal to accrued and unpaid interest, plus
the greater of 100% of the principal amount or the sum of the present values of
the remaining scheduled payments of principal and interest, discounted to the
redemption date on a semi-annual basis at the Treasury Rate, as defined in the
indenture, plus 20 basis points for the 2013 Notes and 25 basis points for the
2018 Notes.
Shortly before these issues, the Company entered into several treasury locks
with a total notional amount of $150.0 million. Upon issuance of the debt, the
treasury locks were settled resulting in the receipt of $5.7 million in cash.
The value received is being amortized as a reduction of interest expense over
the life of the issues.
The net proceeds from the sale of the senior notes and settlement of related
hedging arrangements approximated $203 million.
SIGECO and Indiana Gas Debt Call
During 2003, the Company called two first mortgage bonds outstanding at SIGECO
and two senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond
had a principal amount of $45.0 million, an interest rate of 7.60%, was
originally due in 2023, and was redeemed at 103.745% of its stated principal
amount. The second SIGECO bond had a principal amount of $20.0 million, an
interest rate of 7.625%, was originally due in 2025, and was redeemed at
103.763% of the stated principal amount.
The first Indiana Gas note had a remaining principal amount of $21.3 million, an
interest rate of 9.375%, was originally due in 2021, and was redeemed at
105.525% of the stated principal amount. The second Indiana Gas note had a
principal amount of $13.5 million, an interest rate of 6.75%, was originally due
in 2028, and was redeemed at the principal amount.
Pursuant to regulatory authority, the premiums paid to retire the net carrying
value of these notes totaling $3.6 million were deferred as a regulatory asset.
Other Financing Transactions
In January, 2003, other debt of Indiana Gas totaling $17.5 million and of SIGECO
totaling $1.0 million was retired.
9. Commitments & Contingencies
Legal Proceedings
The Company is party to various legal proceedings arising in the normal course
of business. In the opinion of management, there are no legal proceedings
pending against the Company that are likely to have a material adverse effect on
its financial position or results of operations. See Note 10 regarding
environmental matters.
United States Securities and Exchange Commission (SEC) Informal Inquiry
As more fully described in Note 3 to these consolidated condensed financial
statements and in Note 3 to the 2002 consolidated financial statements filed on
Form 10-K/A, the Company restated its consolidated financial statements for
2000, 2001, and 2002 quarterly results. The Company is cooperating with the SEC
in an informal inquiry with respect to this previously announced restatement,
has met with the staff of the SEC, and has provided information in response to
their requests.
IRS Section 29 Investment Tax Credit Recent Developments
Vectren's Coal Mining operations are comprised of Vectren Fuels, Inc. (Fuels),
which includes its coal mines and related operations and Vectren Synfuels, Inc.
(Synfuels). Synfuels holds one limited partnership unit (an 8.3% interest) in
Pace Carbon Synfuels Investors, LP (Pace Carbon), a Delaware limited partnership
formed to develop, own, and operate four projects to produce and sell coal-based
synthetic fuel utilizing Covol technology. Under Section 29 of the Internal
Revenue Code, manufacturers such as Pace Carbon, receive a tax credit for every
ton of synthetic fuel sold. To qualify for the credits, the synthetic fuel must
meet three primary conditions: 1) there must be a significant chemical change in
the coal feedstock, 2) the product must be sold to an unrelated person, and 3)
the production facility must have been placed in service before July 1, 1998.
In past rulings, the Internal Revenue Service (IRS) has concluded that the
synthetic fuel produced at the Pace Carbon facilities should qualify for Section
29 tax credits. The IRS issued a private letter ruling with respect to the four
projects on November 11, 1997, and subsequently issued an updated private letter
ruling on September 23, 2002.
As a partner in Pace Carbon, Vectren has reflected total tax credits under
Section 29 in its consolidated results through September 30, 2003, of
approximately $35 million. Vectren has been in a position to fully utilize the
credits generated and continues to project full utilization. In addition, Fuels
receives synfuel-related fees from synfuel producers unrelated to Pace Carbon
for a portion of its coal production.
In June 2003, the IRS, in an industry-wide announcement, stated that it would
review the scientific validity of test procedures and results presented as
evidence of significant chemical change. During this review, the IRS suspended
the issuance of new private letter rulings on that subject. In October 2003, the
IRS completed its review and determined that the test procedures and results
used by taxpayers are scientifically valid if the procedures are applied in a
consistent and unbiased manner. Also, the IRS will issue new private letter
rulings based on revised standards. The IRS stated it has continuing concerns
regarding the sampling and data/record retention practices prevalent in the
synthetic fuels industry. The IRS plans to issue guidance extending new
record/data retention requirements to taxpayers already holding private letter
rulings on the issue of significant chemical change.
During June 2001, the IRS began a tax audit of Pace Carbon for the 1998 tax year
and later expanded the audit to include tax years 1999, 2000, and 2001. Based on
conclusions reached in the industry-wide review and recently issued private
letter rulings involving other other synthetic fuel facilities, Vectren believes
chemical change issues from these audits may soon be resolved. However, the IRS
has not directly notified Pace Carbon of any resolution.
Vectren believes that it is justified in its reliance on the private letter
rulings for the Pace Carbon facilities, that the test results that Pace Carbon
presented to the IRS in connection with its private letter rulings are
scientifically valid, and that Pace Carbon has operated its facilities in
compliance with its private letter rulings and Section 29 of the Internal
Revenue Code. However, at this time, Vectren cannot provide any assurance as to
the outcome of these audits concerning the issue of chemical change or any other
issue raised during the audits relative to its investment in Pace Carbon.
Guarantees and Product Warranties
Vectren Corporation issues guarantees to third parties on behalf of its
unconsolidated affiliates. Such guarantees allow those affiliates to execute
transactions on more favorable terms than the affiliate could obtain without
such a guarantee. Guarantees may include posted letters of credit, leasing
guarantees, and performance guarantees. As of September 30, 2003, guarantees
issued and outstanding on behalf of unconsolidated affiliates approximated $6
million. The Company has also issued a guarantee approximating $4 million
related to the residual value of an operating lease that expires in 2006.
Vectren Corporation has accrued no liabilities for these guarantees as they
relate to guarantees issued among related parties or were executed prior to the
adoption of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others" (FIN 45). As more fully described in Note 12, FIN 45 was adopted
prospectively and specifically excludes from its recognition and measurement
provisions guarantees issued among related parties.
Through September 30, 2003, the Company has not been called upon to satisfy any
obligations pursuant to its guarantees. Liabilities accrued for, and activity
related to, product warranties are not significant.
10. Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1999 and 1998.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by investing in
clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months an 8 percent
return on its capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances through a rider mechanism, related to the clean coal
technology once the facility is in service.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated clean coal
technology construction cost is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
September 30, 2003, $117.1 million has been expended. After the equipment is
installed and operational, related annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
Installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology and (3) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleged that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced an agreement that would resolve the lawsuit. The agreement was
embodied in a consent decree filed in U.S. District Court for the Southern
District of Indiana. The mandatory public comment period has expired, and no
comments were received. The Court entered the consent decree on August 13, 2003.
Under the terms of the agreement, the DOJ and USEPA have agreed to drop all
challenges of past maintenance and repair activities at the Culley coal-fired
units. In reaching the agreement, SIGECO did not admit to any allegations
alleged in the government's complaint, and SIGECO continues to believe that it
acted in accordance with applicable regulations and conducted only routine
maintenance on the units. SIGECO has entered into this agreement to further its
continued commitment to improve air quality and avoid the cost and uncertainties
of litigation.
Under the agreement, SIGECO has committed to:
o either repower Culley Unit 1 (50 MW) with natural gas, which would
significantly reduce air emissions from this unit, and equip it with SCR
control technology for further reduction of nitrogen oxides, or cease
operation of the unit by December 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide emissions;
o install a baghouse for further particulate matter reductions at Culley Unit
3 by June 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program and is currently conducting some level of remedial
activities including groundwater monitoring at certain sites where deemed
appropriate and will continue remedial activities at the sites as appropriate
and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's Voluntary Remediation Program (VRP). In
response SIGECO submitted to the IDEM the results of preliminary site
investigations conducted in the mid-1990's. These site investigations confirmed
that based upon the conditions known at the time, the sites posed no risk to
human health or the environment. Follow up reviews have been initiated by the
Company to confirm that the sites continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. At this time the Company
is unable to predict any outcome that may result from these SIGECO manufactured
gas plant sites.
11. Rate and Regulatory Matters
The following is an update on two regulatory matters in Ohio. Each of the
discussed matters is currently pending before the PUCO.
The first matter relates to a pending application made to the PUCO by VEDO,
together with other regulated Ohio gas utilities, for authority to establish a
tariff mechanism to recover expenses related to uncollectible accounts. As
proposed the tariff mechanism would establish an automatic adjustment procedure
to track and recover these costs instead of providing the recovery of the
historic amount in base rates. If the application is approved before the end of
the year, 2003 uncollectible costs in excess of the amount in base rates should
be recovered. While the Company believes there is a sound basis for the PUCO to
grant the application to recover actual expenses relating to uncollectible
accounts, no assurance can be provided with respect to the ultimate outcome of
this proceeding.
The second matter related to the requirement that Ohio gas utilities undergo a
biannual audit of their gas acquisition practices in connection with the gas
cost recovery (GCR) mechanism. In the case of VEDO, the two-year period began in
November 2000, coincident with the Company's acquisition and commencement of
service in Ohio. The audit provides the initial review of the portfolio
administration arrangement between VEDO and ProLiance. The external auditor
retained by the PUCO staff recently submitted an audit report wherein it
recommended a disallowance of approximately $7 million of previously recovered
gas costs. The Company believes a large portion of the third party auditor
recommendations is without merit. There are two elements of the recommendations
relating to the treatment of a pipeline refund and a penalty for which a reserve
of $0.7 million has been established for the Company's estimated share of a
potential disallowance of these costs. For this PUCO audit period, a
disallowance relating to our ProLiance arrangement will be shared by the
Company's joint venture partner. Currently the matter is set for a hearing
before the PUCO in mid November. VEDO has and continues to engage in efforts
with the participants in the proceeding to resolve disputed issues outside of
administrative litigation. If the external auditor recommendations were adopted
by the PUCO, the Company believes that it would not likely have a material
effect on the Company's results or financial condition. However, the Company can
provide no assurance as to the ultimate outcome of this proceeding.
12. Impact of Recently Issued Accounting Guidance
SFAS 143
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of
a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value, and the capitalized cost
is depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The Company adopted this statement on
January 1, 2003. The adoption was not material to the Company's results of
operations or financial condition.
In accordance with regulatory treatment, the Company collects an estimated net
cost of removal of its utility plant in rates through normal depreciation. As of
September 30, 2003 and December 31, 2002, such removal costs approximated $395
million and $385 million, respectively, of accumulated depreciation as presented
in the condensed consolidated balance sheets based upon the Company's latest
depreciation studies.
SFAS 149
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and
clarifies the accounting guidance on (1) derivative instruments (including
certain derivative instruments embedded in other contracts) and (2) hedging
activities that fall within the scope of FASB Statement No. 133 (SFAS 133),
"Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends
SFAS 133 to reflect decisions that were made (1) as part of the process
undertaken by the Derivatives Implementation Group (DIG), which necessitated
amending SFAS 133; (2) in connection with other projects dealing with financial
instruments; and (3) regarding implementation issues related to the application
of the definition of a derivative. SFAS 149 also amends certain other existing
pronouncements, which will result in more consistent reporting of contracts that
are derivatives in their entirety or that contain embedded derivatives that
warrant separate accounting. SFAS 149 is effective (1) for contracts entered
into or modified after June 30, 2003, with certain exceptions and (2) for
hedging relationships designated after June 30. The guidance is to be applied
prospectively. The adoption did not have a material effect on the Company's
financial statements.
SFAS 150
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150).
SFAS 150 requires issuers to classify as liabilities the following three types
of freestanding financial instruments: mandatorily redeemable financial
instruments; obligations to repurchase the issuer's equity shares by
transferring assets; and certain obligations to issue a variable number of
shares. SFAS 150 is effective immediately for all financial instruments entered
into or modified after May 31, 2003. For all other instruments, SFAS 150 applies
to the Company's third quarter of 2003. The Company has approximately $200,000
of outstanding preferred stock of a subsidiary that is redeemable on terms
outside the Company's control. However, the preferred stock is not redeemable on
a specified or determinable date or upon an event that is certain to occur.
Therefore, SFAS 150's adoption did not affect the Company's results of
operations or financial condition.
FIN 45
In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for
a guarantor's accounting for and disclosure of certain guarantees issued and
outstanding and that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligations it has undertaken.
The initial recognition and measurement provisions are applicable on a
prospective basis to guarantees issued or modified after December 31, 2002.
Since that date, the adoption has not had a material effect on the Company's
results of operations or financial condition. The incremental disclosure
requirements are included in these financial statements in Note 9.
FIN 46
In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable
Interest Entities" (FIN 46). FIN 46 addresses consolidation by business
enterprises of variable interest entities (VIE) and significantly changes the
consolidation requirements for those entities. FIN 46 is intended to achieve
more consistent application of consolidation policies related to VIE's and, thus
improves comparability between enterprises engaged in similar activities when
those activities are conducted through VIE's. FIN 46 currently applies to VIE's
created after January 31, 2003, and to VIE's in which an enterprise obtains an
interest after that date. For entities created prior to January 31, 2003, FIN 46
is to be adopted on December 31, 2003.
The Company has neither created nor obtained an interest in a VIE since January
31, 2003. Certain other entities that the Company was involved with prior to
that date, including limited partnership investments that operate affordable
housing projects, are still being evaluated to determine if the entity is a VIE
and, if so, if Vectren is the primary beneficiary. If these entities are
determined to be VIE's and Vectren is determined to be the primary beneficiary,
the effect on the Company's financial statements would not be material.
EITF 03-11
The EITF has recently released guidance on when gross or net presentation on the
income statement for derivative instruments not held for trading purposes is
appropriate. The guidance is effective for the Company's fourth quarter, and the
Company is currently determining the impacts, if any, that will result from
implementing that guidance.
13. Segment Reporting
The Company has four operating segments: 1) Gas Utility Services, (2) Electric
Utility Services, (3) Nonregulated Operations, and (4) Corporate and Other. The
Gas Utility Services segment provides natural gas distribution and
transportation services in nearly two-thirds of Indiana and west central Ohio.
The Electric Utility Services segment includes the operations of SIGECO's
electric transmission and distribution services, which provides electricity
primarily to southwestern Indiana, and SIGECO's power generating and power
marketing operations. The Company collectively refers to its gas and electric
utility services segments as its Regulated Operations. Segments within the
Regulated Operations use operating income as a measure of profitability.
The Nonregulated Operations segment is comprised of various subsidiaries and
affiliates offering and investing in energy marketing and services, coal mining,
utility infrastructure services, and broadband communications among other
energy-related opportunities. The Corporate and Other segment, among other
activities, provides general and administrative support and assets, including
computer hardware and software, to the Company's other operating segments. The
Nonregulated Operations and Corporate and Other segments use net income as a
measure of profitability. The Company makes decisions on finance and dividends
at the corporate level.
Following is information regarding the Company's segments' operating data.
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- --------------------
In millions 2003 2002 2003 2002
- ----------------------------------- ------------------- --------------------
Operating Revenues
Gas Utility Services $ 115.7 $ 88.5 $ 790.3 $ 586.7
Electric Utility Services 134.0 189.6 343.6 475.3
- ------------------------------------------------------------------------------------
Total Regulated 249.7 278.1 1,133.9 1,062.0
- ------------------------------------------------------------------------------------
Nonregulated Operations 50.2 44.2 151.1 300.7
Corporate & Other 6.9 4.9 20.6 16.3
Intersegment Eliminations (28.0) (22.9) (80.9) (64.2)
- ------------------------------------------------------------------------------------
Total operating revenues $ 278.8 $ 304.3 $1,224.7 $1,314.8
====================================================================================
Measure of Profitability
Operating Income
Gas Utility Services $ (14.9) $ (11.2) $ 54.6 $ 55.6
Electric Utility Services 32.4 39.8 71.6 74.6
- ------------------------------------------------------------------------------------
Total Regulated operating income 17.5 28.6 126.2 130.2
- ------------------------------------------------------------------------------------
Regulated other income (expense)-net (1.1) 0.7 (2.1) 4.9
Regulated interest expense (15.7) (15.4) (46.6) (47.0)
Regulated income taxes 0.7 (5.1) (30.2) (31.0)
- ------------------------------------------------------------------------------------
Regulated net income 1.4 8.8 47.3 57.1
- ------------------------------------------------------------------------------------
Nonregulated net income 5.7 5.8 17.6 14.6
Corporate & other net income (loss) 0.2 (1.1) 2.2 (0.1)
- ------------------------------------------------------------------------------------
Net income $ 7.3 $ 13.5 $ 67.1 $ 71.6
====================================================================================
Following is the Company's segments' identifiable assets.
September 30, December 31,
In millions 2003 2002
- ------------------------------------ --------------------------------
Identifiable Assets
Gas Utility Services $ 1,486.9 $ 1,570.1
Electric Utility Services 896.5 869.2
- --------------------------------------------------------------------------
Total Regulated 2,383.4 2,439.3
- --------------------------------------------------------------------------
Nonregulated Operations 426.5 419.6
Corporate & Other 376.9 393.3
Intersegment Eliminations (254.8) (325.7)
- --------------------------------------------------------------------------
Total identifiable assets $ 2,932.0 $ 2,926.5
==========================================================================
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Description of the Business
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an
energy and applied technology holding company headquartered in Evansville,
Indiana. The Company was organized on June 10, 1999, solely for the purpose of
effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc.
(SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into
Vectren was consummated with a tax-free exchange of shares and has been
accounted for as a pooling-of-interests in accordance with APB Opinion No. 16
"Business Combinations" (APB 16).
The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI),
serves as the intermediate holding company for its three operating public
utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned
subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company
(SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio
operations. VUHI also has other assets that provide information technology and
other services to the three utilities. Both Vectren and VUHI are exempt from
registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding
Company Act of 1935.
Indiana Gas provides natural gas distribution and transportation services to a
diversified customer base in 49 of Indiana's 92 counties. SIGECO provides
electric generation, transmission, and distribution services to 8 counties in
southwestern Indiana, including counties surrounding Evansville, and
participates in the wholesale power market. SIGECO also provides natural gas
distribution and transportation services to 10 counties in southwestern Indiana,
including counties surrounding Evansville. The Ohio operations, owned as a
tenancy in common by Vectren Energy Delivery of Ohio, Inc.(VEDO), a wholly owned
subsidiary, (53 % ownership) and Indiana Gas (47 % ownership), provide natural
gas distribution and transportation services to 17 counties in west central
Ohio, including counties surrounding Dayton.
The Company is also involved in nonregulated activities in four primary business
areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure
Services, and Broadband. Energy Marketing and Services markets natural gas and
provides energy management services, including energy performance contracting
services. Coal Mining mines and sells coal to the Company's utility operations
and to other parties and generates IRS Code Section 29 investment tax credits
relating to the production of coal-based synthetic fuels. Utility Infrastructure
Services provides underground construction and repair, facilities locating, and
meter reading services. Broadband invests in broadband communication services
such as analog and digital cable television, high-speed Internet and data
services, and advanced local and long distance phone services. In addition, the
nonregulated group has other businesses that provide utility services, municipal
broadband consulting, and retail products and services and that invest in
energy-related opportunities, real estate, and leveraged leases.
Consolidated Results of Operations
The following discussion and analysis should be read in conjunction with the
unaudited condensed consolidated financial statements and notes thereto.
Subsequent to the issuance of the Company's 2002 quarterly financial statements,
the Company's management determined that previously issued financial statements
should be restated. The restatement had the effect of decreasing net income for
the three and nine months ended September 30, 2002, by $0.5 million after tax
and $2.3 million after tax, respectively. Note 3 to the consolidated condensed
financial statements includes a summary of the effects of the restatement. The
Company's results of operations give effect to the restatement.
- ----------------------------------------------------------------------------------------
Three Months Nine Months
Ended September 30, Ended September 30,
------------------------ ---------------------
In millions, except per share amounts 2003 2002 2003 2002
- -------------------------------------- ------------------------ ---------------------
As Restated As Restated
----------- -----------
Net income $ 7.3 $ 13.5 $ 67.1 $ 71.6
Attributed to:
Utility Group $ 2.4 $ 9.0 $ 51.1 $ 59.7
Nonregulated Group 5.7 5.8 17.6 14.6
Corporate & Other Group (0.8) (1.3) (1.6) (2.7)
- ----------------------------------------------------------------------------------------
Basic earnings per share $ 0.10 $ 0.20 $ 0.97 $ 1.06
Attributed to:
Utility Group $ 0.03 $ 0.13 $ 0.74 $ 0.88
Nonregulated Group 0.08 0.09 0.26 0.22
Corporate & Other Group (0.01) (0.02) (0.03) (0.04)
Net Income
For the three months ended September 30, 2003, net income was $7.3 million, or
$0.10 per share, compared to net income of $13.5 million, or $0.20 per share,
for the same period last year. For the nine months ended September 30, 2003,
reported earnings were $67.1 million, or $0.97 per share, compared to $71.6
million, or $1.06 per share, for the same period in 2002. The 2003 third quarter
and year-to-date results declined $0.10 per share and $0.09 per share,
respectively, reflecting principally a decrease in Utility Group earnings.
Quarter over quarter, Utility Group earnings were primarily affected by a
decrease in electric margin of $7.3 million ($4.3 million after-tax), or $0.06
per share. This was attributable to milder cooling weather, which reduced margin
an estimated $3.6 million pre-tax, or $0.03 per share, the effects of the slowly
recovering economy, and slightly lower wholesale power margins. The remaining
Utility Group decrease for the quarter was due to higher depreciation and the
timing of operating expenses. Year-to-date, the timing of operating expenses and
higher depreciation have been offset somewhat by increased power marketing
margins and favorable weather.
Quarterly and year-to-date, Nonregulated Group earnings remained consistent due
primarily to increased synfuel-related earnings and earnings recorded on the
sale of the Company's investment in Genscape, Inc. (Genscape), a company that
provides real-time power plant and transmission line status information using
wireless technology.
In the first and second quarters of 2003, the Company incurred charges related
to a Utility Group investment in BABB International, Inc. (BABB), an entity that
processes fly ash into building materials and a Nonregulated Group investment in
First Mile Technologies (First Mile), a small broadband entity located in
Indianapolis, Indiana. Total charges affecting year-to-date results, net of the
current quarter gain recognized on the sale of Genscape, were $1.5 million ($0.9
million after tax) or $0.01 per share.
In addition to the above, the Company finalized an equity offering of
approximately 7.4 million shares during the third quarter. The offering netted
proceeds of approximately $163 million and has reduced earnings per share as
compared to the previous year by approximately $0.01 per share for the quarter
and $0.02 year to date.
Dividends
Dividends declared for the three months ended September 30, 2003, were $0.275
per share compared to $0.265 per share for the same period in 2002. Dividends
declared for the nine months ended September 30, 2003, were $0.825 per share
compared to $0.795 per share for the same period in 2002. In October 2003, the
Company's board of directors increased its quarterly dividend to $0.285 per
share from $0.275 per share.
Detailed Discussion of Results of Operations
Following is a more detailed discussion of the results of operations of the
Company's Utility Group and Nonregulated Group. The detailed results of
operations for the Utility Group and Nonregulated Group are presented and
analyzed before the reclassification and elimination of certain intersegment
transactions necessary to consolidate those results into the Company's
Consolidated Condensed Statements of Income. The operations of the Corporate and
Other Group are not significant.
Results of Operations of the Utility Group
The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations,
which consist of the Company's regulated operations (the Gas Utility Services
and Electric Utility Services operating segments), and components of the
Corporate and Other operating segment. Gas Utility Services provides natural gas
distribution and transportation services in nearly two-thirds of Indiana and
west central Ohio. Electric Utility Services provides electricity primarily to
southwestern Indiana, and includes the Company's power generating and marketing
operations. Corporate and Other Operations provides information technology and
other support services to those utility operations. The results of operations of
the Utility Group before certain intersegment eliminations and reclassifications
for the three and nine months ended September 30, 2003 and 2002, follow.
- -----------------------------------------------------------------------------
Three Months Nine Months
Ended September 30, Ended September 30,
In millions, ------------------- --------------------
except per share amounts 2003 2002 2003 2002
- -------------------------------- ------------------- --------------------
OPERATING REVENUES
Gas revenues $ 115.7 $ 88.5 $ 790.3 $ 586.7
Electric revenues 134.0 189.6 343.6 475.3
Other revenues 0.2 - 0.6 0.2
- -----------------------------------------------------------------------------
Total operating revenues 249.9 278.1 1,134.5 1,062.2
- -----------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas 72.0 45.7 541.4 358.3
Fuel for electric generation 24.9 22.8 66.3 59.7
Purchased electric energy 42.6 93.0 101.8 239.5
Other operating 51.4 49.0 161.9 149.1
Depreciation & amortization 30.4 27.8 88.8 80.9
Taxes other than income taxes 9.2 9.5 41.8 37.6
- -----------------------------------------------------------------------------
Total operating expenses 230.5 247.8 1,002.0 925.1
- -----------------------------------------------------------------------------
OPERATING INCOME 19.4 30.3 132.5 137.1
OTHER INCOME (EXPENSE) - NET
Equity in losses of
unconsolidated affiliates (0.1) (0.4) (0.5) (0.9)
Other - net 2.3 0.7 1.0 6.5
- -----------------------------------------------------------------------------
Total other income (expense)
- net 2.2 0.3 0.5 5.6
- -----------------------------------------------------------------------------
Interest expense 17.1 16.9 49.5 51.8
- -----------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 4.5 13.7 83.5 90.9
- -----------------------------------------------------------------------------
Income taxes 2.1 4.7 32.4 31.2
- -----------------------------------------------------------------------------
NET INCOME $ 2.4 $ 9.0 $ 51.1 $ 59.7
=============================================================================
BASIC EARNINGS PER SHARE $ 0.03 $ 0.13 $ 0.74 $ 0.88
=============================================================================
Utility Group earnings for the third quarter 2003 were $2.4 million as compared
to $9.0 million for the same quarter last year, a decrease of $6.6 million. As
noted previously, the primary contributors to the decline are mild electric
cooling weather, a slowly recovering economy, and the timing of certain
operating costs.
Utility Group earnings for the nine months ended September 30, 2003, were $51.1
million as compared to $59.7 million for the same period in 2002, a decrease of
$8.6 million. Earnings in 2003 were primarily driven by weather that on the year
was favorably impacted by an estimated $3.6 million after tax compared to last
year and increased wholesale power and other margins, offset by the BABB
investment write-off of $2.3 million after tax and the timing of certain
operating costs.
Significant Fluctuations
Utility Margin
Gas Utility Margin
Gas utility margin by customer type and separated between volumes sold and
transported follows:
- ------------------------------------------------------------------------------
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- --------------------
In millions 2003 2002 2003 2002
- -------------------------------- --------------------- --------------------
Residential $ 26.7 $ 26.8 $ 159.2 $ 146.6
Commercial 7.2 7.6 50.3 47.5
Contract 9.7 7.8 33.6 32.2
Other 0.1 0.5 5.8 2.1
- ------------------------------------------------------------------------------
Total gas utility margin $ 43.7 $ 42.7 $ 248.9 $ 228.4
==============================================================================
Volumes in MMDth
- ------------------------------
Sold 7.3 7.2 85.8 74.9
Transported 17.8 19.3 63.6 65.4
- ------------------------------------------------------------------------------
Total throughput 25.1 26.5 149.4 140.3
==============================================================================
Gas margins for the third quarter, a non-heating, base load usage quarter, were
$43.7 million, an increase of 2% compared to the prior year period. While margin
was generally flat and reflects a $0.7 million charge associated with a PUCO GCR
audit proceeding in 2003, residential and commercial usage increased slightly,
offset by declining industrial usage due to the slow economic conditions.
Gas margins year-to-date were $248.9 million, an increase of $20.5 million over
the nine months ended September 30, 2002. It is estimated that weather, 19%
colder than the prior year and 8% colder than normal, contributed $12.6 million
to the increased margin. The remaining $7.9 million increase is primarily
attributable to higher utility receipts and excise taxes on higher gas costs and
volumes sold and recovery of Ohio customer choice implementation costs,
partially offset by the negative effect of high gas prices on customer usage.
The colder weather is the primary reason for the 6% increase in throughput.
Higher gas costs and a slowly recovering economy have impacted customer usage.
The average cost per dekatherm of gas purchased for the three months ended
September 30, 2003, was $6.22 compared to $3.95 in 2002. Year-to-date the cost
of gas purchased in 2003 was $6.44 compared to $4.39 in the prior year.
Electric Utility Margin
Electric utility margin by customer type and non-firm wholesale margin separated
between realized margin and mark-to-market gains and losses follows:
- -------------------------------------------------------------------------------
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
In millions 2003 2002 2003 2002
- --------------------------------- ------------------- -------------------
Retail & firm wholesale $ 63.7 $ 70.0 $ 160.5 $ 169.2
Non-firm wholesale 2.8 3.8 15.0 6.9
- -------------------------------------------------------------------------------
Total electric utility margin $ 66.5 $ 73.8 $ 175.5 $ 176.1
===============================================================================
Non-firm wholesale margin:
Realized margin $ 3.3 $ 4.0 $ 14.6 $ 10.0
Mark-to-market gains (losses) (0.5) (0.2) 0.4 (3.1)
Electric margins were $66.5 million, a decrease of $7.3 million compared to the
third quarter of 2002. The decrease in electric margin was due primarily to the
effect of milder cooling weather which was 7% cooler than normal and 26% cooler
than last year. The estimated quarter over quarter decrease as a result of the
milder weather was approximately $3.6 million. Impacts of the slowly recovering
economy on industrial sales and slightly lower non-firm wholesale power margins
further decreased non-weather related electric margin compared to the prior
year. As a result primarily of mild weather, volumes sold to retail and firm
wholesale customers decreased 8% from 1.87 GWh in 2002 to 1.72 GWh in 2003.
Electric margins were $175.5 million, a decrease of $0.6 million over the nine
months ended September 30, 2002. The decrease was primarily due to lower retail
sales due to milder cooling weather and the current quarter decrease in
industrial sales. As a result primarily of the mild weather which was 18% cooler
than normal and 33% cooler than last year, volumes sold to retail and firm
wholesale customers decreased 5% from 4.76 GWh in 2002 to 4.53 GWh in 2003 with
an estimated margin decrease of $6.5 million. The decrease was partially offset
by increased non-firm wholesale power margins resulting from price volatility.
Periodically, generation capacity is in excess of that needed to serve retail
and firm wholesale customers. The Company markets this unutilized capacity to
optimize the return on its owned generation assets. The contracts entered into
are primarily short-term purchase and sale transactions that expose the Company
to limited market risk. For the three months ended September 30, 2003, volumes
sold into the wholesale market were 1.01 GWh compared to 2.66 GWh in 2002 while
volumes purchased were 1.01 GWh in 2003 compared to 2.65 GWh in 2002. For the
nine months ended September 30, 2003, volumes sold into the wholesale market
were 3.04 GWh compared to 8.30 GWh in 2002 while volumes purchased were 3.49 GWh
in 2003 compared to 8.14 GWh in 2002. A portion of volumes purchased in the
wholesale market is used to serve retail and firm wholesale customers, and in
2003, greater amounts of purchased power have been required for native load due
to scheduled outages, which has reduced capacity available for optimization.
Additionally, both sold and purchased power were lower in 2003 due to a shorter
term focus in hedging and optimization strategies combined with a more selective
approach to counter-party relationships. While volumes both sold and purchased
in the wholesale market have decreased during 2003, which has resulted in
decreased electric revenues and purchased power, margins year-to-date have
increased primarily from price volatility. In the third quarter, margins
decreased because less capacity was available for optimization due to outages
for NOx control equipment installation and the wholesale power market was less
volatile.
Utility Group Operating Expenses
Other Operating
For the three and nine months ended September 30, 2003, other operating expenses
increased $2.4 million and $12.8 million, respectively, compared to the same
periods in the prior year. The increased expenses were principally due to the
timing of routine expenditures between the periods and increased employee
benefit costs. Year-to-date, the timing of maintenance expenditures, Ohio
customer choice program implementation costs that are recovered through margins,
and increased uncollectible accounts expense have also contributed to the
increase. Year-to-date uncollectible accounts expense has increased $1.7 million
compared to the prior year due principally to higher gas costs.
Depreciation & Amortization
For the three and nine months ended September 30, 2003, depreciation and
amortization increased $2.6 million and $7.9 million, respectively, due to
additions to utility plant. Increased depreciation expense reflects a full nine
months of depreciation on the addition of over $100 million of utility plant
placed into service including a new gas-fired peaker unit, expenditures for
implementing a choice program for Ohio gas customers, customer system upgrades,
and other upgrades to existing transmission and distribution facilities.
Taxes Other Than Income Taxes
For the nine months ended September 30, 2003, taxes other than income taxes
increased $4.2 million compared to the prior year. The increase results from
higher utility receipts and excise taxes as a result of higher gas prices and
more volumes sold. The higher utility receipts and excise taxes on gas volumes
sold are recovered dollar-for-dollar through customer billings.
Utility Group Other Income (Expense)-Net
For the three and nine months ended September 30, 2003, other income
(expense)-net increased $1.9 million and decreased $5.1 million, respectively,
compared to the prior year. The year-to-date decrease is primarily the result of
the write-off of the BABB investment totaling $3.9 million. The remaining
decrease results principally from sales of emission allowances and other assets
in the second quarter of 2002 totaling $1.8 million and current year
contributions of $1.2 million made to low income heating assistance programs
pursuant to a settlement previously approved by the IURC regarding transactions
with ProLiance Energy LLC. These decreases were offset somewhat by the current
quarter increase in other income (expense)-net which was principally the result
of fluctuations in investments used to fund deferred compensation plans.
Utility Group Interest Expense
For the three and nine months ended September 30, 2003, interest expense
increased $0.2 million and decreased $2.3 million, respectively, when compared
to the same periods last year. The changes reflect the impact of the permanent
financing completed in the third quarter of 2003 and lower short-term borrowing
rates.
Utility Group Income Tax
For the three months ended September 30, 2003, federal and state income taxes
decreased $2.6 million primarily due to fluctuations in pre-tax income. For the
nine months ended September 30, 2003, income taxes increased $1.2 million when
compared to 2002. The year-to-date change is primarily due to an increased
effective tax rate, offset by less pre-tax income. Year to date, the effective
tax rate increased from 34.3% in 2002 to 38.8% in 2003 principally due to an
increase in the Indiana state income tax rate from 4.5 % to 8.5% that was
effective January 1, 2003.
Environmental Matters
Clean Air Act
NOx SIP Call Matter
The Clean Air Act (the Act) requires each state to adopt a State Implementation
Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS)
for a number of pollutants, including ozone. If the USEPA finds a state's SIP
inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its
SIP (a SIP Call).
In October 1998, the USEPA issued a final rule "Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed.
Reg. 57355). This ruling found that the SIP's of certain states, including
Indiana, were substantially inadequate since they allowed for nitrogen oxide
(NOx) emissions in amounts that contributed to non-attainment with the ozone
NAAQS in downwind states. The USEPA required each state to revise its SIP to
provide for further NOx emission reductions. The NOx emissions budget, as
stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx
emissions from Indiana.
In June 2001, the Indiana Air Pollution Control Board adopted final rules to
achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP
requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by
May 31, 2004 (the compliance date). This is a 65% reduction from emission levels
existing in 1999 and 1998.
The Company has initiated steps toward compliance with the revised regulations.
These steps include installing Selective Catalytic Reduction (SCR) systems at
Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4,
and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx
emissions to atmospheric nitrogen and water using ammonia in a chemical
reaction. This technology is known to be the most effective method of reducing
NOx emissions where high removal efficiencies are required.
The IURC has issued orders that approve:
o the Company's project to achieve environmental compliance by investing in
clean coal technology;
o a total capital cost investment for this project up to $244 million
(excluding AFUDC), subject to periodic review of the actual costs incurred;
o a mechanism whereby, prior to an electric base rate case, the Company may
recover through a rider that is updated every six months an 8 percent
return on its capital costs for the project; and
o ongoing recovery of operating costs, including depreciation and purchased
emission allowances through a rider mechanism, related to the clean coal
technology once the facility is placed into service.
Based on the level of system-wide emissions reductions required and the control
technology utilized to achieve the reductions, the current estimated clean coal
technology construction cost is consistent with amounts approved in the IURC's
orders and is expected to be expended during the 2001-2006 period. Through
September 30, 2003, $117.1 million has been expended. After the equipment is
installed and operational, related annual operating expenses, including
depreciation expense, are estimated to be between $24 million and $27 million. A
portion of those expenses began in October 2003 when the Culley SCR became
operational. The 8 percent return on capital investment approximates the return
authorized in the Company's last electric rate case in 1995 and includes a
return on equity.
The Company expects to achieve timely compliance as a result of the project.
Construction of the first SCR at Culley was placed into service in October 2003,
and construction of the Warrick 4 and Brown SCR's is proceeding on schedule.
Installation of SCR technology as planned is expected to reduce the Company's
overall NOx emissions to levels compliant with Indiana's NOx emissions budget
allotted by the USEPA. Therefore, the Company has recorded no accrual for
potential penalties that may result from noncompliance.
Culley Generating Station Litigation
In the late 1990's, the USEPA initiated an investigation under Section 114 of
the Act of SIGECO's coal-fired electric generating units in commercial operation
by 1977 to determine compliance with environmental permitting requirements
related to repairs, maintenance, modifications, and operations changes. The
focus of the investigation was to determine whether new source review permitting
requirements were triggered by such plant modifications, and whether the best
available control technology was, or should have been used. Numerous electric
utilities were, and are currently, being investigated by the USEPA under an
industry-wide review for compliance. In July 1999, SIGECO received a letter from
the Office of Enforcement and Compliance Assurance of the USEPA discussing the
industry-wide investigation, vaguely referring to an investigation of SIGECO and
inviting SIGECO to participate in a discussion of the issues. No specifics were
noted; furthermore, the letter stated that the communication was not intended to
serve as a notice of violation. Subsequent meetings were conducted in September
and October 1999 with the USEPA and targeted utilities, including SIGECO,
regarding potential remedies to the USEPA's general allegations.
On November 3, 1999, the USEPA filed a lawsuit against seven utilities,
including SIGECO. SIGECO's suit was filed in the U.S. District Court for the
Southern District of Indiana. The USEPA alleged that, beginning in 1992, SIGECO
violated the Act by (1) making modifications to its Culley Generating Station in
Yankeetown, Indiana without obtaining required permits (2) making major
modifications to the Culley Generating Station without installing the best
available emission control technology and (3) failing to notify the USEPA of the
modifications. In addition, the lawsuit alleged that the modifications to the
Culley Generating Station required SIGECO to begin complying with federal new
source performance standards at its Culley Unit 3. The USEPA also issued an
administrative notice of violation to SIGECO making the same allegations, but
alleging that violations began in 1977.
On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA
announced an agreement that would resolve the lawsuit. The agreement was
embodied in a consent decree filed in U.S. District Court for the Southern
District of Indiana. The mandatory public comment period has expired, and no
comments were received. The Court entered the consent decree on August 13, 2003.
Under the terms of the agreement, the DOJ and USEPA have agreed to drop all
challenges of past maintenance and repair activities at the Culley coal-fired
units. In reaching the agreement, SIGECO did not admit to any allegations
alleged in the government's complaint, and SIGECO continues to believe that it
acted in accordance with applicable regulations and conducted only routine
maintenance on the units. SIGECO has entered into this agreement to further its
continued commitment to improve air quality and avoid the cost and uncertainties
of litigation.
Under the agreement, SIGECO has committed to:
o either repower Culley Unit 1 (50 MW) with natural gas, which would
significantly reduce air emissions from this unit, and equip it with SCR
control technology for further reduction of nitrogen oxides, or cease
operation of the unit by December of 2006;
o operate the existing SCR control technology recently installed on Culley
Unit 3 (287 MW) year round at a lower emission rate than that currently
required under the NOx SIP Call, resulting in further nitrogen oxide
reductions;
o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for
additional removal of sulphur dioxide emissions;
o install a baghouse for further particulate matter reductions at Culley Unit
3 by June of 2007;
o conduct a Sulphuric Acid Reduction Demonstration Project as an
environmental mitigation project designed to demonstrate an advance in
pollution control technology for the reduction of sulfate emissions; and
o pay a $600,000 civil penalty.
The Company anticipates that the settlement would result in total capital
expenditures through 2007 in a range between $16 million and $28 million. Other
than the $600,000 civil penalty, which was accrued in the second quarter of
2003, the implementation of the settlement, including these capital expenditures
and related operating expenses, are expected to be recovered through rates.
Information Request
On January 23, 2001, SIGECO received an information request from the USEPA under
Section 114 of the Act for historical operational information on the Warrick and
A.B. Brown generating stations. SIGECO has provided all information requested,
and no further action has occurred.
Manufactured Gas Plants
In the past, Indiana Gas and others operated facilities for the manufacture of
gas. Given the availability of natural gas transported by pipelines, these
facilities have not been operated for many years. Under currently applicable
environmental laws and regulations, Indiana Gas and others may now be required
to take remedial action if certain byproducts are found above the regulatory
thresholds at these sites.
Indiana Gas has identified the existence, location, and certain general
characteristics of 26 gas manufacturing and storage sites for which it may have
some remedial responsibility. Indiana Gas has completed a remedial
investigation/feasibility study (RI/FS) at one of the sites under an agreed
order between Indiana Gas and the IDEM, and a Record of Decision was issued by
the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at
additional sites, Indiana Gas has submitted several of the sites to the IDEM's
Voluntary Remediation Program and is currently conducting some level of remedial
activities including groundwater monitoring at certain sites where deemed
appropriate and will continue remedial activities at the sites as appropriate
and necessary.
In conjunction with data compiled by environmental consultants, Indiana Gas has
accrued the estimated costs for further investigation, remediation, groundwater
monitoring, and related costs for the sites. While the total costs that may be
incurred in connection with addressing these sites cannot be determined at this
time, Indiana Gas has recorded costs that it reasonably expects to incur
totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas' proportionate share of
the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26
sites with other potentially responsible parties (PRP), which serve to limit
Indiana Gas' share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded
settlements from all known insurance carriers in an aggregate amount
approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material
impact on earnings since costs recorded to date approximate PRP and insurance
settlement recoveries. While Indiana Gas has recorded all costs which it
presently expects to incur in connection with activities at these sites, it is
possible that future events may require some level of additional remedial
activities which are not presently foreseen.
In October 2002, the Company received a formal information request letter from
the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO
and not currently enrolled in the IDEM's Voluntary Remediation Program (VRP). In
response SIGECO submitted to the IDEM the results of preliminary site
investigations conducted in the mid-1990's. These site investigations confirmed
that based upon the conditions known at the time, the sites posed no risk to
human health or the environment. Follow up reviews have been initiated by the
Company to confirm that the sites continue to pose no such risk.
On October 6, 2003, SIGECO filed applications to enter four of the manufactured
gas plant sites in IDEM's VRP. The remaining site is currently being addressed
in the VRP by another Indiana utility. SIGECO is adding its four sites into the
renewal of the global Voluntary Remediation Agreement that Indiana Gas has in
place with IDEM for its manufactured gas plant sites. At this time the Company
is unable to predict any outcome that may result from these SIGECO manufactured
gas plant sites.
Rate and Regulatory Matters
The following is an update on two regulatory matters in Ohio. Each of the
discussed matters is currently pending before the PUCO.
The first matter relates to a pending application made to the PUCO by VEDO,
together with other regulated Ohio gas utilities, for authority to establish a
tariff mechanism to recover expenses related to uncollectible accounts. As
proposed the tariff mechanism would establish an automatic adjustment procedure
to track and recover these costs instead of providing the recovery of the
historic amount in base rates. If the application is approved before the end of
the year, 2003 uncollectible costs in excess of the amount in base rates should
be recovered. While the Company believes there is a sound basis for the PUCO to
grant the application to recover actual expenses relating to uncollectible
accounts, no assurance can be provided with respect to the ultimate outcome of
this proceeding.
The second matter related to the requirement that Ohio gas utilities undergo a
biannual audit of their gas acquisition practices in connection with the gas
cost recovery (GCR) mechanism. In the case of VEDO, the two-year period began in
November 2000, coincident with the Company's acquisition and commencement of
service in Ohio. The audit provides the initial review of the portfolio
administration arrangement between VEDO and ProLiance. The external auditor
retained by the PUCO staff recently submitted an audit report wherein it
recommended a disallowance of approximately $7 million of previously recovered
gas costs. The Company believes a large portion of the third party auditor
recommendations is without merit. There are two elements of the recommendations
relating to the treatment of a pipeline refund and a penalty for which a reserve
of $0.7 million has been established for the Company's estimated share of a
potential disallowance of these costs. For this PUCO audit period, a
disallowance relating to our ProLiance arrangement will be shared by the
Company's joint venture partner. Currently the matter is set for a hearing
before the PUCO in mid November. VEDO has and continues to engage in efforts
with the participants in the proceeding to resolve disputed issues outside of
administrative litigation. If the external auditor recommendations were adopted
by the PUCO, the Company believes that it would not likely have a material
effect on the Company's results or financial condition. However, the Company can
provide no assurance as to the ultimate outcome of this proceeding.
Results of Operations of the Nonregulated Group
The Nonregulated Group is comprised of four primary business areas: Energy
Marketing and Services, Coal Mining, Utility Infrastructure Services, and
Broadband. Energy Marketing and Services markets natural gas and provides energy
management services, including energy performance contracting services. Coal
Mining mines and sells coal to the Company's utility operations and to other
parties and generates IRS Code Section 29 investment tax credits relating to the
production of coal-based synthetic fuels. Utility Infrastructure Services
provides underground construction and repair, facilities locating, and meter
reading services. Broadband invests in broadband communication services such as
analog and digital cable television, high-speed Internet and data services, and
advanced local and long distance phone services. In addition, the Nonregulated
Group has other businesses that provide utility services, municipal broadband
consulting, and retail products and services and that invest in energy-related
opportunities, real estate, and leveraged leases. The results of operations of
the Nonregulated Group before certain intersegment eliminations and
reclassifications for the three and nine months ended September 30, 2003 and
2002,